The technique of hydraulic fracturing is well known in the art as a means of increasing producing rates from oil and gas wells. The use of resin-coated proppants is also known.
Hydraulic fracturing of a formation adjacent a wellbore increases productivity of desirable hydrocarbon fluids from the subterranean formation by creating channels of high conductivity.
The technique normally involves (1) injecting a fracturing fluid through a well and into the formation at a sufficient rate and pressure to overcome the earth stresses and form a crack (fracture) in the formation; and (2) placing a particulate material(propping agent) in the formation to maintain the fracture in a propped condition when the injection pressure is released. The propped fracture thus provides a highly conductive channel in the formation. The degree of stimulation afforded by the hydraulic fracture treatment is largely dependent upon the permeability and the width of the propped fracture.
Often the fracturing fluid is a viscous liquid. Fracturing fluids used in conventional hydraulic fracturing techniques include: fresh water, brine, liquid hydrocarbons (e.g., gasoline, kerosene, diesel, crude oil, alcohols and the like) and foams which are viscous or have gelling agents incorporated therein, gelled water, gelled brine and gelled oils, to name a few. The fracturing fluid will also typically contain the particulate proppant material in a portion of the total volume of the fracturing fluid. The proppant flows into and remains in the fissures which are formed and/or enlarged during the fracturing operation. The proppant operates to prevent the fissures from closing completely and thus facilitates the flow of formation fluid through the fissures and into the wellbore.
Examples of particulate materials commonly used as proppants in fracturing include: sand, glass beads, nut shells, metallic pellets or spheres, gravel, synthetic resin pellets or spheres, gilsonite, coke, sintered alumina, sintered bauxite, other ceramic materials, mullite, like materials, and combinations thereof.
The fracturing fluid is pumped into the formation under a pressure sufficient to enlarge natural fissures in the formation and/or open up new fissures in the formation. Packers can be positioned in the wellbore as necessary to direct and confine the fracturing fluid to the portion of the well which is to be fractured. Typically, fracturing pressures range from less than 1,000 psi to over 15,000 psi depending upon the depth and the nature of the formation being fractured.
A properly designed hydraulic fracture treatment places a desired amount of proppant in the formation to hold open the hydraulically created fractures. One of the major difficulties encountered in fracturing is proppant flowback. This decreases the amount of proppant holding the fractures open, allowing closing of the fractures and causing reduced permeability. As production rates increase, proppant flowback into the wellbore and to the surface can occur. Proppant flowback can reduce fracture conductivity and restrict production, erode tubulars and wellhead equipment as well as surface facilities, and can fill treating vessels causing failure of the treating process.
A number of procedures such as placing a screen and liner, using precoated curable resins, adding resins on the fly, and forced closure have been used to reduce the proppant flowback problem. To date, nothing has been found to control all situations and as deeper, hotter wells are treated, the limits of current resin coatings are exceeded.
Resin-coated proppants which have the ability to consolidate have the potential to minimize this problem. They also possess other properties which are advantageous in a proppant. For example, it is desirable that the proppants have relatively high strength so as to resist crushing of the proppant when consolidated. Also, the proppant needs to be compatible with the fracturing fluids used to carry it downhole.
Resin-coated proppants are currently used in many fracturing treatments. The coated materials can be manufactured away from the well site and delivered to the well location or the coating can be added to the proppant on-site by adding required resin material to the fluid so that the coating occurs while the proppant is being pumped, or even after the proppant is pumped downhole.
Failure of resin-coated proppants can occur for a number of reasons. In addition, to the interactions that can occur with the fracturing fluid and its additives, reaction with natural brines, CO.sub.2 and production treating chemicals can further degrade resin strength over time. High temperature accelerates the chemical degradation, and high temperature alone can degrade the resins currently in use.
U.S. Pat. No. 4,785,884 discloses a proppant coated with a solid thermosetting resin that can consolidate and cure at temperatures below about 130.degree. F.
In U. S. Pat. Nos. 4,585,064 and 4,717,594 there are disclosed high strength self-consolidating particles comprised of a particulate substrate, a substantially cured inner resin coating and a fusible curable outer resin coating.
In U.S. Pat. No. 5,048,608, there is disclosed a proppant consolidating fluid mixture for use in hydraulic fracturing which contains a quasi polyurethane prepolymer, a diluent, and a diol. This system can be cured at low temperatures.
Well treatment methods for continuously forming and transporting consolidatable resin coated particulate material are disclosed for example, in U.S. Pat. Nos. 5,128,390 and 4,336,842. Hardenable resin systems are also disclosed in U.S. Pat. Nos. 4,199,484; and 4,665,988.
In U.S. Pat. Nos. 4,664,819; 4,564,459 and 4,443,347, there is disclosed pre-cured proppants and methods for employing them to prop a fracture.
In U.S. Pat. No. 4,427,069, there is disclosed a method for consolidation of sand naturally existing in an earth formation adjacent a producing well, utilizing as a polymerizable resin, a furfuryl alcohol oligomer, which produced a strong and durable resin bonding the sand grains together while maintaining sufficient permeability to permit the production of fluid from the formation. In U.S. Pat. No. 4,428,427, there is disclosed a gravel pack employing a similar resin to precoat gravel or other particulate matter and introduce fluid comprising the suspended granular material into the washed-out zone or cavity adjacent to the producing well.
With the resin-coated proppant systems now available in the art, a problem which contributes to proppant flowback is that the systems may not allow sufficient time for the curable resin coated proppants to come together before the resin cures and the proppants cannot bond together to properly form a three dimensional matrix. Particularly in low permeability, high temperature formations, the time required for close contact can be longer than the time to set. These problems are even more apparent with the increasing demand to perform hydraulic fracturing in hotter, deeper wells.
In an SPE publication, SAND CONTROL, Vol. 1, Henry L. Doherty Series, Ch. 11, 1992, there is an article titled, "PLASTIC CONSOLIDATION PRINCIPLES", by W. L. Penberthy, Jr., and C. M. Chaughnessy, in which it is stated at page 67 that the upper temperature useful for polymers known in the field of hydraulic fracturing is about 300.degree. F. In the same publication, at page 76, it is stated that furans or phenolic furans are very reactive . . . and no method is available to control them internally, such as, for example, in a well. This would appear to summarize the prevalent view of the art in this field. That is, that resin-coated gravels have potential for minimizing proppant flowback and that furan resins might be very useful, but they are unmanageable above about 300.degree. F.
It would fill a need in the art if there were a hydraulic fracturing system available which used curable resin coated proppants which would be essentially inert to strong chemicals used in wells and stable at high temperatures. It would also be very valuable in the art if the cure times could be tailored to suit various conditions.